The bulk of the world's liquid petroleum resources are located in heavy oil and oil sand reservoirs. While some of this resource can be recovered by highly geotolerant recovery processes such as mining, these procedures are typically only economic for shallow resources, are very costly, produce high carbon dioxide emissions, use large volumes of water, and incur other environmental penalties. Most of the world's heavy oil and bitumen resource is buried too deeply to mine and so in situ recovery methods predominate. Conventional in situ recovery of viscous and poor quality oils currently relies on either high pressure primary production, as in cold heavy oil production, or thermal and/or solvent-based methods to mobilize the oil by reducing its viscosity.
A defining characteristic of heavy oil and bitumen reservoirs is the significant variation of oil composition and thus fluid properties, such as oil viscosity, that is observed both vertically and laterally throughout the reservoirs. As stated in Darcy's law, the oil phase flow rate in the reservoir does not depend entirely on the permeability, but rather is directly proportional to the oil phase mobility; that is, the quotient of the oil phase effective permeability and its viscosity. In heavy oil and bitumen reservoirs, the variability of the oil phase viscosity can be substantially larger than the variation in effective permeability. Therefore, a controlling factor on production, especially by methods relying on gravity drainage, can be the oil phase viscosity.
Fluid properties commonly vary by orders of magnitude across the thickness of a reservoir, or laterally over the distance of a single horizontal production well. These substantial variations are often not taken into account (e.g., oil phase viscosity is assumed constant throughout the reservoir) when designing the operating strategy or well placement for recovery processes, even though these variations can have significant effects on production. The poor recoveries and prediction of production targets seen in many current thermal operations may be partly related to disregarding the natural variation in oil quality in heavy oil and bitumen reservoirs when designing and optimizing production strategies. In highly compositionally graded heavy oil and bitumen reservoirs, proper consideration of fluid property variations, in addition to comprehensive characterization of reservoir properties, can facilitate geotailored design of recovery methods, including well placement and optimization production strategies for each reservoir to lower operational costs and improve recovery of these viscous oils.
Thus, the incorporation of oil and bitumen viscosity variations into production planning is now being used by some in many areas of the world. The need for high resolution viscosity profiles of bitumens and heavy oils in situ has correspondingly increased.
There are several methods for recovering bitumen and oils from core samples for direct viscosity measurement with a viscosimeter, viscometer or rheometer. These methods typically involve core sample centrifugation or compaction, or displacement of the oil with an immiscible viscous fluid (mechanical recovery techniques). For samples of low viscosity, these methods can be useful. However, where the reservoir is of low permeability and/or the bitumen sample is of very high viscosity, and/or the bitumen or oil saturation of the pore space is very low and/or the core is sufficiently lithified to inhibit significant compaction, these mechanical recovery procedures are not effective. In addition, if the core sample is too small (e.g., side wall core samples) to yield sufficient bitumen to directly measure viscosity, alternative methods are required to characterize the core-hosted oil. For instance, mechanical recovery is typically ineffective for Canadian bitumen-containing carbonate reservoirs of the Devonian Grosmont Formation.
Another method for recovering oil or bitumen for analysis is the use of solvent extraction. However, since a solvent dramatically lowers the viscosity of a bitumen sample, no method has been reported which can successfully recover an accurate dead oil bitumen viscosity from analysis of solvent-containing oils. Dead oil refers to a produced oil sample where all or substantially all of the solution gas has exsolved and added solvent has been removed and the sample is at standard atmospheric pressure (1 atm) and temperature (15° C.). Prior methods of using solvent to measure viscosity of oil or bitumen were unsuccessful largely because the solvent was not completely removed prior to viscometry, or the process of solvent removal also removed volatile components in the bitumen, thus affecting the apparent dead oil viscosity. As a result, the viscosity measurement of solvent-extracted oil is generally inaccurate.
Similar problems occur for measuring density of solvent-extracted oil and such measurements are also generally inaccurate. There is therefore a need for an accurate method to measure the true dead oil bitumen viscosity and density and other properties for bitumen-containing reservoirs. There is also a need to accurately measure true viscosity and density of solvent-free oils collected by solvent-extraction.